There are many systems for transporting fluids from an offshore structure such as a ship or other platform to an undersea pipeline. Examples of such systems include:                (1) The conventional multi-buoy mooring (CMBM) system. In this system a riser runs directly from the offshore structure down to the pipeline, with supporting buoys arranged at intervals along the length of the hose.        (2) The single tower mono-mooring (STM) system. In this system a mooring tower is fixed to the seabed and extending to the surface of the sea. The mooring tower supports a riser extending from the surface of the sea to the pipeline. A hose or other pipe can extend from the offshore structure and be connected to the end of the hose at the top of the mooring tower.        (3) The single anchor-leg mooring (SALM) system. In this system, a buoy is located close to the offshore structure, the buoy being attached to, and supporting, a connector unit located on or near the seabed. A riser extends from the offshore structure to the connecting unit, then from the connecting unit to the pipeline. A further section of pipe runs from the connector unit to the pipeline.        (4) The catenary anchor-leg mooring (CALM) system. In this system, a buoy is located close to the offshore structure. A riser runs from the buoy to an underwater connector unit usually located on or near the seabed. A further section of pipe runs from the connector unit to the pipeline. A hose or other pipe can extend from the offshore structure and be connected to the end of the hose at the buoy. There are various configurations of the CALM system including the “Steep S” system, the “Lazy S” system and the “Chinese Lantern” system.        
All the systems described above are well known in the art, and there are other possible systems that are not described above such as, for example, the use of an intermediate offshore structure. The essential feature of all these systems is that a riser is provided to deliver fluids from an offshore structure, such as a ship, to an underwater structure, such as a pipeline. The exact configuration of the riser, and of the support structure for the riser, can be varied depending prevailing conditions at the particular offshore location. Depending on the particular details of the system the riser comprises of submerged, floating and aerial sections.
Pipelines are generally constructed by one of two methods. The first and generally the most common method for both onshore and offshore pipelines is by welding together short lengths of metal pipe. This metal pipe may be coated for corrosion protection and often in marine applications there is a concrete coating for weight and mechanical protection. In some applications a thick coating such as syntactic polyurethane is applied for insulation. A coating is usually applied after a joint is made. In offshore construction the joints are either made in the substantially horizontal position from the lay barge (the so called “S lay” method) or in the near vertical position (the so called “J lay” method). The J lay method is usually the preferred method in deep water pipeline construction.
The alternative to the joining of short pipe sections on the offshore lay barge is the reeling method where the continuous pipeline is stored with some plastic deformation on a large reel. When the pipeline is unspooled from the reel it passes through a straightener to reverse the plastic deformation from storage.
In some applications the demands on insulation both in terms of thermal properties and water depth capacity is such that pipe-in-pipe systems have developed. Here a relatively short length of pipe is placed inside another pipe and they are joined together to make the continuous pipeline. The annulus between the concentric pipes may be either filled with insulation or be a vacuum.
Comparatively short onshore pipelines for cryogenic applications are common and these are typically constructed from austenitic stainless steels which are suitable for service at temperatures associated with liquid nitrogen at about −196° C. and liquefied natural gas at about −163° C. A known problem with onshore cryogenic pipeline applications is the thermal contraction as the pipeline is cooled from ambient temperature to the temperature of the conveyed liquefied natural gas. For austenitic stainless steels this is equivalent to a contraction of about 2.8 mm/m. In order to control the resulting thermal stresses expansion loops are regularly placed in the pipeline. A more recent development by Osaka Gas and others is to use pipelines made from an alloy of 36% nickel and 64% iron. This alloy is also known under the trade name of INVAR (Registered Trade Mark). This alloy, discovered in 1896 by Charles-Edouard Guillaume, has the property of minimal dimensional changes with temperature variations. When cooled from ambient temperature to the temperature of liquefied natural gas the contraction is 0.3 mm/m, an order of magnitude less than austenitic stainless steel. This is particularly advantageous in that it substantially reduces the need for extensive use of expansion loops.
Being metals, austenitic stainless steels and INVAR® have no effective insulation properties and therefore either conventional insulation is applied or the pipeline is allowed to self insulate with the build up of a layer of ice.
Thus, the common problems for subsea cryogenic pipes are as follows:
1) The material in contact with the cryogenic fluid must not be brittle at LN2 temperatures;
2) There must be a very efficient insulation between the cryogenic fluid and the external seawater temperature to miniminse the boil off resulting from heat influx as a result of the circa 200° C. temp differential (−163 for LNG to sea water temp of about 10° C. say=a difference of 173° C.);
3) The contraction in the axial/longitudinal direction of the pipeline, i.e., along the pipeline must be controlled otherwise, because the pipeline is effectively restrained at both ends huge forces develop when cooled down because it wants to shrink but it cannot.
As discussed above, the conventional solution to (1) is to use austenitic stainless steels, e.g., 316L, 9% nickel and Nickel 36% (Invar) for the inner pipe. All of these are compatible with the cryogenic conditions but with reducing thermal contraction coefficients from austenitic stainless steel to invar. 316 contracts too much and therefore dogleg expansion loops are needed to handle the third problem. Invar eliminates the problem because of its nominally zero thermal contraction coefficient and Ni9% is somewhere between—see background papers.
The second problem is addressed by placing the inner pipe inside a outer pipe and addressing the insulating properties of the annulus. This is the so called pipe in pipe solution and it is the focal area of a number of patents. One option is to form a vacuum in the annulus which is an very effective means of insulation. The alternative is to use very efficient insulators of which there are several (see the patent literature) and recent focus is now on a relatively new insulating material which is called aerogel or nanogel. These insulating materials have also been combined with a partial vacuum to provide the insulating materials.
In essence the known technology is a pipe in pipe solution with annulus insulation.
To date no marine pipelines have been built for cryogenic applications. A marine pipeline for conveying cryogenic fluids has to address the two problems of thermal expansion and insulation. This has led to the development of concentric pipe designs based on the conventional pipe-in-pipe design. These designs use INVAR® to solve the thermal expansion problem and high performance insulating materials such as aerogels in the resulting annuli are used to address the insulation problem. These designs are expensive in terms of materials and construction.